GENERAL INTEREST Quick Takes
ExxonMobil earns $23 billion in 2021
Exxon Mobil Corp. had fourth-quarter 2021 earnings of $8.9 billion, up from $6.7 billion in third-quarter 2021, and resulting in full-year earnings of $23 billion. Capital and exploration expenditures were $5.8 billion in the fourth quarter and $16.6 billion for the full year 2021, in line with guidance.
The company generated $48 billion of cash flow from operating activities for the year, the highest level since 2012, including $17.1 billion for fourth-quarter 2021.
For full-year 2021, the company paid down $20 billion in debt, including $9 billion in the fourth quarter, returning the balance sheet to pre-pandemic levels of less than $48 billion.
Capital spending for 2022 is expected to be $21-24 billion, an increase over 2021, with the largest increase in spending to come from increasing activity in the Permian basin and Brazil. The operator plans to spend $1 billion in lower-emission investments across all segments.
Oil-equivalent production in the fourth quarter was 3.8 million b/d. Excluding entitlement effects, divestments, and government mandates, oil-equivalent production increased 2% versus the prior-year quarter, and was also up 2% versus the prior year, driven by demand recovery.
In 2021, production volumes in the Permian basin increased nearly 100,000 boe/d to about 460,000 boe/d with improved capital efficiency.
Energy Transfer requests extension to complete Lake Charles LNG
Energy Transfer LP affiliate Lake Charles LNG Co. LLC and Trunkline Gas Co. LLC have requested that the US Federal Energy Regulatory Commission grant an extension to Dec. 16, 2028, to complete construction of Energy Transfer’s proposed 16.45-million tonne/year (tpy) liquefaction plant and associated pipeline modifications. The companies cited the impact of global market conditions on their ability to reach final investment decision and secure long-term offtake contracts in making the request.
The plant and pipeline modifications were originally supposed to have entered service by Dec. 17, 2020, but the companies were granted permission in December 2019 to extend both to Dec. 16, 2025. Energy Transfer has been considering reducing the plant’s size to 11 million tpy (OGJ, Aug. 2, 2021, p. 55).
Liquefaction would be adjacent to Lake Charles LNG’s existing LNG terminal in Calcasieu Parish, La. Pipeline modifications include construction of 17.9 miles of pipeline; construction of a new 103,175-hp compressor station; and installation an additional 12,900 hp of compression at the 3,000-hp Longville compressor station. Pipeline segments include 11.44 miles of 42-in. OD greenfield pipeline (Mainline Connector) and 6.45 miles of 24-in. OD loop (Mainline 200-3 Loop).
The companies have obtained all federal, state, and local permits related to the projects.
EGPC acquires Wintershall DEA Egypt oil interests
Egyptian General Petroleum Corp. (EGPC) acquired shares of Gulf of Suez oil concessions in Egypt from Wintershall Dea Egypt, as part of Wintershall’s strategy to focus on natural gas production in Egypt.
Suez Oil Co. (SUCO), a joint venture between EGPC and Wintershall, held Ras Budran and Zeit Bay concessions in the Gulf of Suez for 38 years. Transfer of sale is effective Jan. 1, 2022.
Ras Budran offshore facilities consist of three unmanned well head platforms and one manned production platform. Production streams from the well head platforms are commingled and fed to a single production platform. On the production platform liquid and gas is separated and evacuated to shore in separate pipelines.
Zeit Bay offshore facilities consist of four unmanned well head platforms which are in the entrance to the bay. Production from the platforms is through high pressure or low-pressure pipelines.
Wintershall will continue to hold 17.25% of the offshore West Nile Delta gas concession and operate the onshore Nile Delta Disouq gas concession held by SUCO. Exploration will continue at East Damanhour, onshore Nile Delta.
Gazprom to explore lithium production, processing
Gazprom has inked agreements to advance lithium production at Kovyktinskoye gas field in eastern Russia. The project is part of the operator’s strategy to provide the country’s industrial complex with domestically-produced rare metals and rare earth metals by 2030—a goal set by the Russian government.
On the heels of an October 2021 memorandum of intent signed by Gazprom and Irkutsk Oil Co. to implement a joint project for production and processing of formation brines (saline groundwaters) from the field to obtain lithium compounds, an agreement of cooperation was signed this month by Alexey Miller, chairman of the Gazprom Management Committee, and Denis Manturov, Minister of Industry and Trade of the Russian Federation.
A tripartite action plan was signed by Gazprom, Irkutsk Oil, and the Ministry of Industry and Trade of the Russian Federation. The parties will cooperate in research and development activities aimed at creating domestic technologies, equipment, and materials required to implement the project, as well as drawing up proposals regarding state support.
Russia currently imports all the lithium consumed nationwide. As demand for lithium is expected to grow, development of domestic technological expertise in the field of lithium production is important, Miller said in a Feb. 3 release.
A feasibility study has been completed, and initial estimates suggest such a project may cover the bulk of domestic demand for lithium in the long run, Miller said.
Gazprom holds the subsurface use license of Kovyktinskoye. Recoverable gas reserves at the field are 1.8 trillion cu m. Kovyktinskoye serves as the basis for the Irkutsk gas production center and, together with Chayandinskoye field in Yakutia, forms the resource base for the Power of Siberia gas pipeline.
Exploration & Development Quick Takes
Shell discovers light oil offshore Namibia
Shell Namibia Upstream BV discovered light oil in the primary and secondary targets of the Graff-1 deep-water exploration well offshore Namibia. Laboratory analyses will be performed and a possible second exploration well could help with understanding of the reservoir quality and potential flow rates achievable, according to the National Petroleum Corp. of Namibia (NAMCOR), the Namibian state-owned oil company.
Graff-1 proved a working petroleum system for light oil in the Orange basin, 270 km off the coast of Oranjemund. Drilling operations began early December 2021 and were completed in early February 2022.
Shell Namibia holds a 45% participating interest in PEL 39, offshore Namibia, with a 45% interest held by QatarEnergy, and 10% interest held by NAMCOR.
Shell completed three seismic surveys of PEL 39 between 2014 and 2019.
TotalEnergies, CNOOC reach FID on Uganda crude development
TotalEnergies SE, China National Offshore Oil Corp. (CNOOC), Uganda National Oil Co. (UNOC), and Tanzania Petroleum Development Corp. (TPDC) have taken final investment decision on the Lake Albert development project in Uganda. Lake Albert development includes Tilenga and Kingfisher oil projects and construction of the East African crude oil pipeline (EACOP) through Uganda and Tanzania.
Tilenga, operated by TotalEnergies, and Kingfisher, operated by CNOOC, are expected to start producing in 2025 and reach a cumulative plateau production of 230,000 b/d. Upstream partners are TotalEnergies (56.67%), CNOOC (28.33%) and UNOC (15%). Production from the oil fields in Uganda will be transported to the port of Tanga, Tanzania, through EACOP (TotalEnergies, 62%; UNOC, 15%; TPDC, 15%; and CNOOC, 8%) for export.
EACOP will use 897 miles of heated 24-in. OD pipe to carry as much as 300,000 b/d from western Uganda to Tanga on the Indian Ocean.
TotalEnergies says Lake Albert project design will limit greenhouse gas emissions “well below” 20 kg CO2eq/boe. Planned measures include extraction of LPG for use in regional markets as a substitute for burning biomass and solarization of the EACOP pipeline, according to TotalEnergies.
The company expects the project to cost $10 billion.
TotalEnergies last year let an engineering, procurement, construction, and commissioning contract for Tilenga to a consortium of a subsidiary of McDermott International Ltd. and Sinopec International Petroleum Service Corp. Tilenga includes six oil fields and will be developed using 31 well pads connected to a 190,000-b/d central processing facility (CPF) in Kasenyi, Uganda. A planned 426 wells will be in use at full production: 200 water-injection wells, 196 production wells, two polymer-pilot wells, and 28 reference wells.
Kingfisher development area (KFDA) includes Kingfisher field in Kikuube District, Uganda, with plans for future tie-in of Mputa-Nzizi-Waraga fields in Kaiso-Tonya, Hoima District. China Offshore Oil Engineering Co. completed Kingfisher’s front-end engineering design in November 2017.
KFDA development will use a 40,000-b/d CPF, 31 wells (11 injectors, 20 producers) to be drilled from four well pads, 19 km of flowline connecting the fields to the CPF, and a 46-km, 12-in. OD pipeline from the CPF to a planned hub and 30,000-b/d refinery in Kabaale, Hoima District.
A 211-km pipeline will move products from the refinery to a storage terminal at Namwabula, Mpigi District.
An airport is being built in Kabaale to help with refinery construction.
TotalEnergies and the Ugandan Ministry of Energy and Minerals also signed an MOU for development of 1 Gw of renewable energy.
Petrobras plans deep offshore Brazil development
Petrobras is entering the development stage in its deep offshore block BM-SEAL-4 (Budião), in Brazil’s Sergipe Alagoas basin with a declaration of commerciality.
Block development calls for installation of a shared FPSO and a gas pipeline. The development module is in the contract planning phase and is expected to start production after 2026.
Petrobras, as operator with 75% interest, made a major gas discovery in the block in 2019. Partners are NGC Videsh Ltd., a subsidiary of Oil and Natural Gas Corp. Ltd., holds the remaining 25%.
Drilling & Production Quick Takes
Shell outlines plans for new gas drilling phase onshore Queensland
Shell PLC’s Queensland Gas Co. (QGC) will enter a new phase of drilling for gas onshore Queensland to maintain supply to the Australian domestic market as well as feedstock for its LNG export business on Curtis Island.
Between this year and 2024, the operator plans to progressively drill and connect about 145 new gas wells as part of its coal seam gas business in the Western Downs region of Surat basin, which is centered on Miles and Chinchilla west of Brisbane.
The planned wells will be connected to existing processing plants and are expected to supply a total of 210 petajoules of gas over the next 15 years.
All required state and federal government environmental approvals are in place and discussions with landholders are under way to secure access and agree on well locations to minimize impact on farming activities.
Shell’s QGC operation currently includes over 3,000 production wells, 25 field compressor stations, six central processing plants, two water treatment plants, and the two-train LNG export plant on Curtis Island near Gladstone.
Shell is operator and majority interest holder in QGC. Partners in the LNG plant are CNOOC with 50% equity in Train 1 and Tokyo Gas with 2.5% equity in Train 2.
Canacol ties in latest Colombia production well
Canacol Energy Ltd. tied in the Toronja 2 gas well to the production manifold for produciton in Colombia’s Lower Magdalena Valley (LMV) basin.
The development well spudded Jan. 17, targeting the Porquero sandstone reservoir. It reached 6,899 ft measured depth and encountered 29 ft true vertical depth of net gas pay with an average porosity of 28% within the primary target.
The rig is currently mobilizing to drill the Carambolo 1 exploration well targeting gas bearing sandstones within the Cienaga de Oro sandstone reservoir. The well is expected to take about 4 weeks to drill, complete, and test.
Following completion of Carambolo 1, the rig will move to the Arandala 3 development well, which Canacol anticipates spudding in March. It will take about 3 weeks to drill, complete, and tie into permanent production.
LMV basin is in the northwestern part of Colombia and produces dry gas. The basin has at least 20 significant gas fields with more than 20 bcf of gas each, and numerous smaller accumulations, the company said. The primary reservoir consists of thick continental to marginal marine clastics of the Eocene to Lower Miocene-aged Cienaga de Oro (CDO) formation deposited in an active trans-tensional setting directly on basement. Regionally, the CDO is overlain by thick marine shales of the Porquero formation, which provides top seal lithology.
Canacol is operator of all blocks in LMV basin and has an exploration and production contract with the National Hydrocarbons Agency.
Lukoil increases hydrocarbon production year-on-year, quarter-on-quarter
LUKOIL Group’s hydrocarbon production for 2021, excluding the West Qurna-2 project, was 2.16 MMboed, which is 4.7% higher year-on-year. Fourth-quarter 2021 hydrocarbon production increased by 7.6% quarter-on-quarter.
In 2021 oil production, excluding West Qurna-2, was 79.3 million tonnes, which is 3% higher year-on-year in average daily terms, while fourth-quarter 2021 oil production increased by 5.3% quarter-on-quarter to 21.1 million tonnes. Oil production dynamics were driven by the April 2020 OPEC+ agreement which led to limitations on oil production by the Group in Russia and at certain international projects. Oil production by the group in Russia was cut in May 2020 by about 310,000 b/d, or by 19%, as compared to first-quarter 2020, and has been gradually recovering subsequently. As a result, fourth-quarter 2021 oil production by the group in Russia was about 270,000 b/d higher compared to May 2020.
In West Siberia, total oil and gas condensate production in 2021 at V. Vinogradov, Imilorskoye, Sredne-Nazymskoye, and Pyakyakhinskoye fields increased by 8.1% year-on-year, to 4.5 million tonnes.
In 2021, gas production increased in average daily terms by 11.2% year-on-year to 32.2 billion cu m. The growth was driven by recovery of gas production in Uzbekistan after temporary decline in 2020 due to lower demand from China for gas produced in Uzbekistan amid the COVID-19 pandemic.
In fourth-quarter 2021, gas production increased by 12.7% quarter-on-quarter to 8.6 billion cu m. The increase was mainly attributable to seasonal growth of demand for gas, as well as higher associated petroleum gas production following an increase in oil production.
In 2021, refinery throughput at LUKOIL Group’s refineries was 63 million tonnes, which is 7.4% higher year-on-year. The increase in refinery throughput volumes both in and outside Russia was attributable to higher refineries utilization rates due to better market environment in 2021, as well as scheduled maintenance works in 2020. In fourth-quarter 2021, refinery throughput was 15.5 million tonnes, which is 10.5% lower quarter-on-quarter due to scheduled maintenance works at the refineries outside Russia, as well as seasonal throughput optimization in Russia.
PROCESSING Quick Takes
Thailand’s PTT lets contract for new Rayong gas processing plant
PTT Public Co. Ltd. (PTT), through its contractor, has let a contract to Lummus Technology LLC to deliver technologies and other services for units to be included as part of a grassroots natural gas processing plant to be built at the operator’s existing complex in Map Ta Phut, Rayong Province, Thailand.
As part of the contract awarded by project contractor CCC-JV—a joint venture of China Petroleum Pipeline Engineering Co. Ltd. (CPP), China Petroleum Pipeline Bureau Co. Ltd. (CPPB), and China Petroleum Engineering & Construction Corp. (CPECC)—Lummus will license its proprietary NGL-MAX and NGL fractionation technologies, as well as provide basic engineering and related services, for the NGL recovery and fractionation units of PTT’s proposed seventh gas separation (GSP-7) plant, the service provider said on Jan. 27.
The NGL-MAX and NGL fractionation technologies will enable the planned GSP-7 plant to recover cold energy from its 460-MMcfd LNG feedstock to enable increased energy efficiency and reduced carbon intensity in production of high-purity ethane, propane, and various LPG and natural gas condensates, according to Lummus.
The technology licensing contract to Lummus follows PTT’s announcement on Sept. 23, 2021, of its $282-million contract award to the CCC-JV consortium of CPP, CPPB, and CPECC to serve as main engineering procurement, and construction (EPC) contractor on the GSP-7 project.
Scheduled for a construction period of 27 months from the time of the EPC contract award and to be built on about 180,000 sq m within PTT’s Map Ta Phut complex, GSP-7 will receive its feed gas—all of which is produced from the Gulf of Thailand—directly from the terminal of its existing Rayong gas separation plant operations to recover ethane and fractionate heavier hydrocarbons into propane, LPG, NGLs, and condensates for use as petrochemical feedstocks and fuel (e.g., cooking gas), according to official project documents from PTT.
Officially approved in December 2020 at a budget of 13.7 billion baht, GSP-7 will replace current production capacity of PTT’s first GSP at Map Ta Phut—GSP-1, for which Lummus also served as technology licensor—which has been operating for more than 30 years, PTT said.
Scheduled for startup in 2023, GSP-7 will be followed by commissioning in 2025 of the operator’s proposed GSP-8, according to the operator’s latest presentation to investors.
While complete details of GSP-8 have yet to be disclosed, the project will include another LNG extraction unit for ethane and LPG, as well as the addition of ethane storage and receiving installations to enhance ethane-import capacity, PPT said in a mid-December 2021 filing to the Stock Exchange of Thailand.
PTT current operates six GSPs in Thailand at two locations. With an overall nameplate processing capacity of 2.66 bcfd, the plants currently operate at a combined processing capacity of 2.87 bcfd due to efficiency improvements.
Repsol awaits approval to restart crude deliveries to Peruvian refinery
Repsol SA is awaiting approval from the Peruvian government to resume port activities at the nearby maritime terminal of subsidiary Refinería La Pampilla SAA’s 117,000-b/d refinery in the Ventanilla district of El Callao, Peru, following a mid-January oil spill that has since left terminal operations shuttered.
As of Feb. 3., Repsol has submitted all required documentation to government officials regarding the operator’s revised contingency and management plans for hydrocarbon spills at sea and was awaiting direction regarding restart of port activities at Terminal Marítimo La Pampilla’s terminals 1, 3, and 4, none of which were impacted by the spill, Repsol said in a series of releases.
In a live broadcast on Feb. 4, José Reyes, La Pampilla refinery’s senior manager of safety, quality, and environment, confirmed progress in cleanup efforts has resulted in Repsol revising its completion date for cleanup of the sea environment offshore Pasamayo—just north of Lima—to Feb. 15 from an earlier end-February estimate.
Beach cleanup activities at Costa Azul, Ventanilla, Cavero, Pachacutec, Bahía Blanca, Playa Chica, Playa Grande, Isla Mata Cuatro, Balneario Marina Sur, Balneario de la Marina, Norte Miramar, Pocitas, and Conchitas continue to progress, with additional resources added daily to advance efforts, according to the latest situation reports.
Based on the latest figures posted to its website, Repsol—along with its partners from more than 50 international companies specializing in oil-spill containment, government agencies, and local volunteers—has recovered about 40% of the estimated 10,386-bbl volumes that spilled from the Mare Doricum vessel on Jan. 15.
While Repsol has yet to explicitly confirm the status of La Pampilla refinery operations following the halt to crude offloadings at the connected marine terminal, the operator did reiterate in its situation updates the necessity to resume “[maritime] activities as soon as possible” to avoid risk of essential product shortages to the Peruvian market.
The La Pampilla refinery’s production accounts for about 40% of the Peruvian fuels market, Repsol said.
Further details regarding an anticipated timeframe for government approvals to restart operations at terminals 1, 3, and 4 of the refinery’s maritime terminal have yet to be disclosed.
TRANSPORTATION Quick Takes
Sempra, Mexican government agree to LNG development terms
Sempra Infrastructure, a subsidiary of Sempra Energy, and Mexico’s Federal Electricity Commission (CFE) have signed a nonbinding MOU for development of the 4-million tonne/year (tpy) Vista Pacífico LNG plant in Topolobampo, Sinaloa; a regasification terminal in La Paz, Baja California Sur; and the resumption of operations of the 510-MMcfd Guaymas-El Oro pipeline in Sonora.
Sempra said the development of these projects would allow CFE to optimize excess pipeline capacity from Texas to Topolobampo to increase natural gas supply to its power plants in Baja California Sur.
The Guaymas–El Oro pipeline’s potential return to service follows a rerouting based on agreements reached with the Yaqui Indigenous community. It was shut in 2017 and would supply both the Vista Pacifico plant and consumers on Mexico’s Pacific coast.
Vista Pacifico LNG SAPI de CV in 2020 applied with the US Department of Energy for long-term multi-contract authorization to export as much as 667 MMcfd of US-sourced gas to Mexico and re-export 550 MMcfd as LNG from Topolobampo.
Vista Pacifico would include a single 180,000-cu m storage tank.
Cheniere reaches near completion of Sabine Pass Train 6
Cheniere Energy Partners LP reported it has reached “substantial completion” of Train 6 of the Sabine Pass liquefaction project in Cameron Parish, La. Commissioning has been completed and the Houston firm’s engineering, procurement, and construction partner, Bechtel Oil, Gas & Chemicals Inc., has turned over care, custody, and control of Train 6 to Cheniere.
Cheniere Partners and Bechtel have now declared substantial completion on all six liquefaction trains at Sabine Pass. With the achievement of substantial completion, financial results of liquefied natural gas sales from Train 6 will be reflected in the statement of operations of Cheniere and its affiliates.
Sabine Pass currently has five fully operational liquefaction units, each capable of producing 5 million tonnes/year (tpy) of LNG. When all six trains are completed, the aggregate nominal production capacity of Sabine Pass is expected to be 30 million tpy of LNG, and process more than 4.7 bcfd of natural gas into LNG.
Tellurian to start Driftwood construction in April
Tellurian Inc. will begin building its 27.6-million tonne/year (tpy) Driftwood LNG liquefaction plant in Calcasieu Parish, La., in April 2022, regardless of whether full Phase 1 financing is in place, according to executive chairman Charif Souki. Souki made the remarks in a video posted to Tellurian’s website Feb. 1.
Driftwood LNG would use 20 1.38-million tpy trains developed in five 4-train blocks to reach its maximum planned capacity. Phase 1 (11 million tpy) includes the first two of these blocks, two (of three planned) 235,000-cu m storage tanks, and the first of three planned loading berths.
Bechtel Oil, Gas, and Chemicals Inc. in 2017 signed four lump-sum, fixed-price contracts worth a total of $15.2 billion for engineering, procurement, and construction of Driftwood LNG. Tellurian has 10-year offtake agreements in place totaling 9 million tpy with Shell NA LNG, Vitol Inc., and Gunvor Singapore Pte. Ltd. (OGJ Online, July 30, 2021).
In January 2022 the Sierra Club and a coalition of Louisiana-based environmental groups petitioned the US Environmental Protection Agency to deny Driftwood’s operating permit, citing flaws in the process.